Most producing oil fields utilize an electrically driven downhole pumping system to bring oil to the surface. The pump typically comprises several staged centrifugal pump sections that can be specifically configured to suit the production and wellbore characteristics of a given application. ESP systems are a common artificial-lift method, providing flexibility over a range of sizes and output flow capacities. ESPs are typically used in older reservoirs on wells with high water cuts (percentage of water to oil).
ESPs provide cost effective production by boosting fluid production from these less efficient, older reservoirs. ESP completions are an alternative means of obtaining artificial lift in wells having low bottom hole pressures. ESP completions are the most efficient choice for high volume capable wells. Production rates up to 90,000 barrels (14,500-m3) of fluid per day have been obtained using large ESPs.
The ESP system consists of a number of components that turn a staged series of centrifugal pumps to increase the pressure of the well fluid and push it to the surface. The energy to turn the pump comes from a high-voltage (3-kV to 5-kV) alternating-current source to drive a special motor that can work at high temperatures of up to 300-deg F (150-deg C) and high pressures of up to 5,000-lb/in2 (34-MPa), from deep wells of up to 12,000-ft (3.7-km) deep with high energy requirements of up to about 1,000-hp (750-kW).
The ESP uses a centrifugal pump which is attached to an electric motor and operates while submersed in the well fluid. The sealed electric motor spins a series of impellers. Each impeller in the series forces fluid through a diffuser into the eye of the one above it. In a typical 4-in submersible pump, each impeller will add an approximately 9-psi (60-KPa) of pressure. For example, a typical 10-stage pump will develop a pressure of about 90-psi (600-KPa) at its outlet (i.e. 10 impellers×9-psi). The lift and capacity of the pump is related to impeller diameter and the width of the impeller vanes. The pump pressure is a function of the number of impellers. For example, a ½-hp 7-stage pump may deliver a high volume of water at a low pressure while a ½-hp 14-stage pump will deliver a lower volume, but at a greater pressure. Like all other centrifugal pumps, an increase in well depth or discharge pressure will reduce the capacity.
As one of the higher volume methods of lift, ESPs offer advantages over some other high volume methods because they can create a higher drawdown on the formation and achieve more production. However, they also present problems that must be solved, such as gas interference and sand production.
More than 60 percent of producing oil wells require some type of assisted lift technology to produce the recoverable oil originally in place. In 2000 about 14 percent of some 832,000 wells lifted worldwide are/were lifted with ESPs.
Artificial lift systems are an essential part of production, especially in maturing oil fields where the reserves lack sufficient pressure to easily bring the crude oil to the surface. As the production of natural gas and crude oil continues to diminish and water production increases (particularly in water-driven reservoirs), the lease operator may begin waterflood, an enhanced recovery method in which water is injected into the reservoir at one well to drive hydrocarbons to other wells. Given time, however, oil production will continue to fall and water production will increase. As this occurs, the pumping time for a given beam pump system, for example, increases until the lease pumper is producing the well 24 hours a day. At this time, the most practical way to improve production is to install a system with greater production capability.
Where heavy crudes (up to a point), limited access to injection gas, higher water cut or low bottomhole pressures preclude the gas lift option, an ESP can be used. ESPs generate centrifugal force to pressurize wellbore fluids and are capable of lifting fluids from depths of 20,000-ft (6,100-m) or more. However, installations to 10,000-ft and less are more common.
ESPs are dynamic pumps that use multiple stages to raise the liquid pressure high enough to overcome static head of the discharge column. These pumps were traditionally installed in high-volume artificial-lift applications that are seldom appropriate for deliquifying gas wells.
However, new work from Centrilift shows using ESPs down to 40-bpd to 100-bpd at depth to lift liquids off gas wells. The motor is shrouded, or re-circulated, or just constructed with high temperature trim. The pumps used were higher volume stages run to the left of the curve.
ESP systems may be the best choice for larger oil wells that have declined and desire to increase production, such as the case in many Middle East countries. Older gas lift systems with now high water cut would produce to lower pressure and produce higher recoverable oil if money were spent to reequip them with ESPs. ESPs offer the highest yield of most deep-well artificial lift systems, but suffer the highest frequency of expense and repair. ESP systems also offer superior performance in somewhat gaseous and water-infused environments.
Gas and water occur naturally in high percentages with crude oil. The gas and water must be separated from the flow of crude oil in order to pump it to the surface. High percentages can cause gas locking in the pump mechanism, resulting in a serious decrease in flow delivery—requiring the entire production string to be pulled from the well and re-primed.
The motors for ESPs are specially designed and because of where they are deployed are long and narrow. The motors operate in high temperature applications and need to run for long periods reliably. One issue with these motors is bearing life, which is affected by vibration. Another issue is the limited space around the motor shaft in the motor housing in which any device that dampens such vibration can be disposed.
Efforts in other applications where space is not a significant issue have been undertaken to address dampening shaft vibrations with weights placed on a common sleeve and radially and axially displaced from the shaft axis. These weights were all interdependent because they were fixated to the sleeve and their positions with respect to the sleeve could not be simply adjusted for tuning purposes. The automotive application was also not one where space limitations were an issue. This system is described in U.S. Pat. No. 6,817,771. Various other dampening devices for vibration that have been tried in the past are reflect in U.S. Pat. No. 3,545,301; 5,637,938; 5,595,117; 5,564,537; EP 1,887125A; GB 1, 187326; JP 1998 018961 and U.S. Pat. No. 4,873,798.
The present invention addresses the need to dampen vibrations in a rotating shaft turning in a confined housing and in a potentially hostile environment. The device has flexibility to be tuned so that its natural frequency approximates the vibration frequency of the shaft. Using an adjustment feature the weights can be moved on axially extending cantilevered beams that take up less space in a confined area due to the axial orientation. The vibration of the dampener weights with oil ports in the stationary support structure also adds a potential benefit in improved heat transfer for the bearing oil to dissipate heat through the housing. Those skilled in the art will better appreciate other aspects of the invention from a review of the detailed description of the preferred embodiment and the associated drawings while appreciating that the appended claims describe the full scope of the invention.